Simulations for hydraulic fracturing treatments and methods of fracturing naturally fractured formation

ABSTRACT

A hydraulic fracture design model that simulates the complex physical process of fracture propagation in the earth driven by the injected fluid through a wellbore. An objective in the model is to adhere with the laws of physics governing the surface deformation of the created fracture subjected to the fluid pressure, the fluid flow in the gap formed by the opposing fracture surfaces, the propagation of the fracture front, the transport of the proppant in the fracture carried by the fluid, and the leakoff of the fracturing fluid into the permeable rock. The models used in accordance with methods of the invention are typically based on the assumptions and the mathematical equations for the conventional 2D or P3D models, and further take into account the network of jointed fracture segments. For each fracture segment, the mathematical equations governing the fracture deformation and fluid flow apply. For each time step, the model predicts the incremental growth of the branch tips and the pressure and flow rate distribution in the system by solving the governing equations and satisfying the boundary conditions at the fracture tips, wellbore and connected branch joints. An iterative technique is used to obtain the solution of this highly nonlinear and complex problem.

CROSS REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. provisional application Ser.No. 60/887,008, filed Jan. 29, 2007.

FIELD OF THE INVENTION

This invention relates to methods of treating subterranean formations,and particularly, methods for fracture treatments performed on naturallyfractured formations.

BACKGROUND OF THE INVENTION

The statements in this section merely provide background informationrelated to the present disclosure and may not constitute prior art.

Hydraulic fracturing is the most widely used well stimulation method toenhance hydrocarbon production from oil or gas wells. To achieve thebest economical result from a hydraulic fracturing treatment, modern dayfracturing treatments commonly involve an extensive design process ofacquiring pertinent formation mechanical and stress data, selection ofproper fracturing fluid and propping agents, and designing the pumpingschedule using a design model. The fracture design model plays acritical role which is to ensure the selected fluids and proppant, theiramount, the pump rate and the proppant concentration schedule are alladequate to allow successful proppant placement without prematurescreenout (or proppant bridging) and to achieve the desired fracturelength and conductivity.

Most, if not all, current commercial hydraulic fracture models are basedon the assumption of a single hydraulic fracture plane being created inthe formation being treated. The fracture initiates from the wellboreand grows in length and height over time as the fluid and proppant areinjected into the fracture. The in-situ stress condition in thereservoir is such that there is generally a minimum stress among thethree stress components, and the created hydraulic fracture tends topropagate in the plane normal to the minimum stress. This single planarfracture assumption is generally adequate for fracturing treatments in aformation consisting of laterally homogeneous layers.

In recent years, however, fracturing stimulation activities haveincreased in the unconventional gas shale formations, which contain verylarge gas reserves. These formations often have extremely low matrixpermeability, but contain a large number of natural fractures whichprovide the apparent permeability for the gas production. Due to thenature of very low permeability, these formations cannot produce withouthydraulic fracture stimulation. One of the most successful fracturingtechniques applied in gas shale formations to date is the so-calledslick water light sand treatment, i.e., a fracture treatment that pumpsa very large volume of low-cost slick water with very low proppantconcentration. Microseismic mapping conducted during these treatmentsindicated that a complex network of crisscrossing fractures are created,resulting from the hydraulic fracturing fluid penetrating the existingnatural fracture network. Shown in FIG. 1 is microseismic mapping offracture structures from a treatment in Barnett Shale as reported inFisher, M. K., Wright, C. A., Davidson, B. M., Goodwin, A. K., Fielder,E. O., Buckler, W. S., and Steinsberger, N. P., “Integrating FractureMapping Technologies to Optimize Stimulations in the Barnett Shale,”paper SPE 77441, 2002 SPE Annual Technical Conference and Exhibition,San Antonio, September 29-October 2.

The complex fracture geometry created during these treatments rendersthe traditional single fracture model completely inadequate in terms ofits ability to predict the fracture size or surface area created or thesand placement. While it has been qualitatively established that the gasproduction of a stimulated well is proportional to the area extent ofthe created fracture network based on the microseismic measurements,current design tools are not adequate for designing such jobs.

Early hydraulic fracture models are the so-called 2D models. The mostwidely used 2D models are those described by Perkins, T. K. and Kern, L.R., “Widths of Hydraulic Fractures,” paper SPE 89, Journal of PetroleumTechnology (September 1961) 13, No. 9, p. 937-947, which later wasextended by Nordren (called PKN model), and by Khristianovich andGeertsma and de Klerk (called KGD model), Geertsma, J. and de Klerk, F.,“A Rapid Method of Predicting Width and Extent of Hydraulic InducedFractures,” paper SPE 2458, Journal of Petroleum Technology (December1969) 21, 1571-1581. These 2D models consider either a vertical fractureof constant height or a penny-shaped fracture. The 2D models simplifythe fracture geometry and reduce the fracture growth to one dimension(either length or radius), making the problem much simpler to solve. The2D models are suitable to a formation with strong stress barriers aboveand below to contain the fracture in the zone (typically a sandstonesandwiched between the shales), or a radial fracture propagating in aformation with no stress barriers.

Modern hydraulic fracturing simulators are based on Pseudo-3D (P3D) orfull planar 3D models to properly account for fracture height growth.The planar 3D models solve numerically the full set of 3D governingequations to predict the fracture dimensions and the proppant placementin the fracture. These models are computationally intensive and requirelong computation time, making them less suitable for daily quick jobdesign needs. With today's faster desktop computers, they areincreasingly utilized, especially for complex reservoirs where simplermodels are not adequate. Most of the commercial fracture design softwarepackages today are based on the P3D models. These models are extensionsof the PKN model by considering the fracture height growth. However, thefracture geometry is limited to an ellipse-like shape, and 2Dapproximation of the fracture surface deformation is made instead ofaccurately solving the much more complex 3D fracture surfacedeformation.

Most typical design models simulate a single planar fracture. Nofracture branching or interaction with existing natural fractures arepossible, which are essential features required in order to simulate thecomplex fracturing process in the shale gas formation. For a hydraulicfracture system that contains many jointed branches, the lateralfracture penetration is significantly reduced for a given volume offluid, simply due to mass balance. The fluid loss into the surroundingrock matrix also increases due to the increased surface area, furtherreducing the fracture penetration. Therefore, the single fracture designmodel may not provide adequate prediction of the job outcome.

Therefore, there is a need for methods of fracturing naturally fracturedsubterranean formation using tools which adequately model a fracturenetwork in such formations. This need is met, at least in part, by thefollowing invention.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a representation of microseismic mapping of fracturestructures from a treatment in Barnett Shale.

FIG. 2 is an illustration of created hydraulic fracture network in anaturally fractured formation.

FIG. 3 is a graph of stress distribution along fracture paths for theexample simulation.

FIG. 4 shows simulated fracture length and flow rate history for theexample simulation.

FIG. 5 shows simulated pressure history for the example simulation.

DESCRIPTION OF THE INVENTION

At the outset, it should be noted that in the development of any suchactual embodiment, numerous implementation-specific decisions must bemade to achieve the developer's specific goals, such as compliance withsystem related and business related constraints, which will vary fromone implementation to another. Moreover, it will be appreciated thatsuch a development effort might be complex and time consuming but wouldnevertheless be a routine undertaking for those of ordinary skill in theart having the benefit of this disclosure.

The description and examples are presented solely for the purpose ofillustrating the preferred embodiments of the invention and should notbe construed as a limitation to the scope and applicability of theinvention. While the compositions used in methods of the invention maybe described herein as comprising certain materials, it should beunderstood that the composition could optionally comprise two or morechemically different materials. In addition, the composition can alsocomprise some components other than those cited. In the summary of theinvention and this detailed description, each numerical value should beread once as modified by the term “about” (unless already expressly somodified), and then read again as not so modified unless otherwiseindicated in context. Also, in the summary of the invention and thisdetailed description, it should be understood that a concentration rangelisted or described as being useful, suitable, or the like, is intendedthat any and every concentration within the range, including the endpoints, is to be considered as having been stated. For example, “a rangeof from 1 to 10” is to be read as indicating each and every possiblenumber along the continuum between about 1 and about 10. Thus, even ifspecific data points within the range, or even no data points within therange, are explicitly identified or refer to only a few specific, it isto be understood that inventors appreciate and understand that any andall data points within the range are to be considered to have beenspecified, and that inventors possession of the entire range and allpoints within the range.

This invention relates to methods of treating subterranean formations,and particularly, methods for fracture treatments performed on naturallyfractured formations. Embodiments of the invention incorporate ahydraulic fracture design model that can adequately simulate thepropagation of a complex hydraulic fracture network and the interactionwith the existing natural fracture network.

A hydraulic fracture model is a mathematical model that simulates thecomplex physical process of fracture propagation in the earth driven bythe injected fluid through a wellbore. An objective in the model is toadhere with the laws of physics governing the surface deformation of thecreated fracture subjected to the fluid pressure, the fluid flow in thegap formed by the opposing fracture surfaces, the propagation of thefracture front, the transport of the proppant in the fracture carried bythe fluid, and the leakoff of the fracturing fluid into the permeablerock. Due to the complexity and highly nonlinear nature of theformulated mathematical problem, it is solved through a numericalmethod.

The models used in accordance with methods of the invention are based onthe assumptions and the mathematical equations for the conventional 2Dor P3D models, and further take into account the network of jointedfracture segments. For each fracture segment, the mathematical equationsgoverning the fracture deformation and fluid flow apply. For each timestep, the model predicts the incremental growth of the branch tips andthe pressure and flow rate distribution in the system by solving thegoverning equations and satisfying the boundary conditions at thefracture tips, wellbore and connected branch joints. An iterativetechnique is used to obtain the solution of this highly nonlinear andcomplex problem. The user can utilize these types of fracture models inconjunction with other engineering tools that provide the formationmechanical properties and adequate characterization of the naturalfractures to generate a quantitative prediction of the fracturedimension and the potential production increase resulting from thefracture stimulation.

For a formation at depth, the in-situ stresses in the earth aregenerally such that the vertical overburden stress is greater than thehorizontal stress components. As a result, the hydraulic fractures aregenerally vertical cracks in the formation being treated. When ahydraulic fracture intersects a pre-existing natural fracture, it caneither follow along the natural fracture or cut right through it,depending on various factors such as the angle of the natural fracturerelative to the hydraulic fracture, the normal stress acting on thenatural fracture, the fluid pressure in the hydraulic fracture, theviscosity of the fracturing fluid, the rock mechanical properties, thenatural fracture conductivity, and possibly other factors. The hydraulicfracture may also follow the natural fracture for some distance and thenbranch off again in its preferred direction. If these conditions prevailthroughout the formation, the created hydraulic fracture system may bevery complex as shown in FIG. 1, or may be as illustrated in FIG. 2.

Two major difficulties may be encountered in attempting to model ahydraulic fracture system as depicted in FIG. 2. The first is the pathfor the hydraulic fracture to follow when it intersects a naturalfracture. Detailed analysis of the stresses near the hydraulic fracturetip and the natural fracture intersection, as well as the opening orslippage of the natural fracture faces, is needed to determine whetherthe hydraulic fracture will propagate through or terminate. The seconddifficulty is in the solution of the set of highly non-linear equationsgoverning the fracture opening and the fluid flow in the fracture systemwith jointed branches. Due to the non-linearity of the governingequations, the solution of pressure and flow distribution in thefracture is obtained through numerical iterations and is computationallyintensive even for the simplest case of single planar fracture. For abranched system as shown in FIG. 2, the computation complexity increasesdrastically, since at each joint where multiple branches connect, theflow rate split among the branches is not known. A numerical solutionmethod must determine the flow rates and pressure in all fracturesegments, not only to satisfy the governing equations along eachsegment, but also to satisfy the flow rate balance at each joint andequal pressure drop along the parallel flow paths connecting the joints.

For a complex fracture system such as that shown in FIG. 2, a fullplanar 3D model is impractical at this time since computation timerequired is so large that it will be of little practical use; however,in the future, such models may become more practical. The modelscurrently used in accordance with methods of the invention are simpler2D or P3D type fracture models to allow the solution in a reasonablecomputation time. In one specific embodiment, the 2D PKN type model isused, which renders the mathematical problem much simpler to solve. In a2D PKN model, a constant fracture height H is assumed. This assumptionis valid if the fracture is expected to be contained in the formationbeing treated without significant height growth. For any fracturesegment, the governing equations that relate the flow rate in thefracture Q, the pressure p and the fracture opening width w are given asfollows:

$\begin{matrix}{{{{Flow}\mspace{14mu}{equation}\text{:}}\; - \frac{\mathbb{d}p}{\mathbb{d}s}} = {2\;{k\left( \frac{{4\; n} + 2}{n} \right)}^{n}\left( \frac{Q}{H} \right)^{n}\Phi\frac{1}{w^{{2\; n} + 1}}}} \\{{{Elasticity}\text{:}\mspace{14mu} w} = \frac{\left( {p - {\sigma(s)}} \right)2\; H}{E^{\prime}}} \\{{{{Mass}\mspace{14mu}{balance}\text{:}\mspace{11mu}\frac{\partial}{\partial s}\left( \frac{Q}{H} \right)} + \frac{\partial w}{\partial t} + {2\; v_{l}}} = 0}\end{matrix}$

In these equations, s is the distance, n and k are the fluid rheologyproperties, Φ is shape factor, σ is the normal stress acting on thefracture and can vary along the fracture, and v₁ is the fluid leakoffvelocity. These equations are the same as the conventional PKN model,except that the stress σ is assumed constant in the conventional PKNmodel.

In accordance with some embodiments of the invention, the model operatesby dividing the fracture segments into small elements to form a fracturegrid. The treatment is simulated in small time increments, with thefracture branches growing in length in small steps. Such time incrementsusually consist of a mere second to several minutes in length, typicallyno more than about five or ten minutes, but could be designed to be upto thirty minutes or more if desired. At each time step, the flow rateand pressure distribution throughout the fracture system are solved tosatisfy the governing deformation and flow equations, the boundaryconditions at the tips of the propagating branches and at the wellbore,and the continuity, and flow rate balance at each joint. The solutioncan be obtained through using an iterative scheme, similar to that usedin MLF (Multi-Layer Fracture) model, such as that described by Gu, H.,Desroches, J. and Elbel, J. L, “Computer Simulation of MultilayerHydraulic Fractures,” paper SPE 64789, 2000 International Conference ofOil and Gas in China, Beijing, Nov. 7-10, or a dual-fracture refracmodel described by Weng, X. and Siebrits, E., “Effect ofProduction-Induced Stress Field on Refracture Propagation and PressureResponse,” paper SPE 106043, 2007 SPE Hydraulic Fracturing TechnologyConference, College Station, Jan. 29-31.

In some embodiments of the invention, the following solution scheme isadopted for the model used in the fracturing method. First, eachpropagating branch tip is allowed to advance by a small increment. Thepressure and the flow rate distribution along each branch are determinedfrom the tip or outer joint towards the next inner joint by solving thegoverning equations. A flow rate split among the connecting branches ateach joint has to be assumed to obtain the solution. However, since theassumed flow rate split may not be the correct solution, this wouldresult in the computed pressures at the next joint to be different alongdifferent parallel flow paths. A correction function based on thedifference between the pressure for the branch and the average pressureat the joint can then be used to adjust the flow rate split among theconnecting branches in the next iteration. The iteration repeats untilthe computed pressure drops along all parallel flow paths become equal,and until the computed flow rate at the wellbore equals to the specifiedpump rate.

When a propagating branch tip intersects a natural fracture, a specialfracture tip-natural fracture interaction model is used to determinewhether the fracture will propagate through or follow the naturalfracture path. This model correlation is derived from the results ofother more sophisticated numerical models that simulate the detailedhydraulic fracture-natural fracture interaction process, or derived fromlaboratory and field experiments.

The hydraulic fracture network model described in this inventionprovides a design tool to predict the dimensions and the structure ofthe created fracture system in a naturally fractured formation toachieve the optimal well productivity. The design process can involvethe following steps:

-   -   1. Define and construct the data for the formation layers and        their geomechanical properties through logs;    -   2. Collect all pertinent well completion and reservoir data for        the design;    -   3. Obtain a natural fracture network description (fracture        location, spacing, width, etc.) through wellbore imaging logs,        core description, or natural fracture models;    -   4. Simulate the fracture treatment using the hydraulic fracture        network model described here and the input data from the above        steps; and,    -   5. Optimize the treatment by comparing the predicted fracture        geometry against the design target, or using a production        simulator that can predict the productivity increase for a        naturally fractured system.

The methods of the invention are useful for subterranean formationtreatment, which also includes a wellbore penetrating the formation, andinclude such methods as treatment fluid design, breaker schedule design,rheology representation in treatment simulators, and the like.Preferably, the embodiments of the invention are fracturing methodswhich include design of the fracturing fluid, design of the fracturingtreatment, injection of the fracturing fluid into the wellbore,stimulating the formation, and monitoring/optimizing the fluid/treatmentbased upon real-time monitoring.

Methods of the invention may also be used to for real-time QA/QC of thefluids, thus making possible to adjust the fluid components during anoperation to achieve a further optimized fluid and treatment schedule.The model can be used to further extrapolate monitored surfacecharacteristics such as viscosity, pumping rate, temperature, VESconcentration, polymer concentration, crosslinker concentration, breakerconcentration to bottomhole or formation conditions.

Some fluids used in methods are crosslinked polymer based fluids, orlinear polymer based fluids, used for treating a subterranean formation.The fluids typically include a polymer viscosifying agent and acrosslinker. Non-limiting examples of polymer viscosifiers include guargums, high-molecular weight polysaccharides composed of mannose andgalactose sugars, or guar derivatives such as hydropropyl guar (HPG),carboxymethyl guar (CMG), and carboxymethylhydroxypropyl guar (CMHPG).Cellulose derivatives such as hydroxyethylcellulose (HEC) orhydroxypropylcellulose (HPC) and carboxymethylhydroxyethylcellulose(CMHEC) may also be used. Any useful polymer may be used in eithercrosslinked form, or without crosslinker in linear form. Xanthan,diutan, and scleroglucan, three biopolymers, have been shown to beuseful as viscosifying agents. Synthetic polymers such as, but notlimited to, polyacrylamide and polyacrylate polymers and copolymers areused typically for high-temperature applications. Also, associativepolymers for which viscosity properties are enhanced by suitablesurfactants and hydrophobically modified polymers can be used, such ascases where a charged polymer in the presence of a surfactant having acharge that is opposite to that of the charged polymer, the surfactantbeing capable of forming an ion-pair association with the polymerresulting in a hydrophobically modified polymer having a plurality ofhydrophobic groups, as described published U.S. Pat. App. No. US2004209780, Harris et. al.

When incorporated, the polymer viscosifier may be present at anysuitable concentration. In various embodiments hereof, the viscosifyingagent can be present in an amount of up to less than about 60 pounds perthousand gallons of liquid phase, or from about 15 to less than about 40pounds per thousand gallons, from about 15 to about 35 pounds perthousand gallons, 15 to about 25 pounds per thousand gallons, or evenfrom about 17 to about 22 pounds per thousand gallons. Generally, theviscosifying agent can be present in an amount of from about 1 to lessthan about 50 pounds per thousand gallons of liquid phase, with a lowerlimit of polymer being no less than about 1, 2, 3, 4, 5, 6, 7, 8, 9, 10,11, 12, 13, 14, 15, 16, 17, 18, or 19 pounds per thousand gallons of theliquid phase, and the upper limited being less than about 50 pounds perthousand gallons, no greater than 59, 54, 49, 44, 39, 34, 30, 29, 28,27, 26, 25, 24, 23, 22, 21, or 20 pounds per thousand gallons of theliquid phase. In some embodiments, the polymers can be present in anamount of about 20 pounds per thousand gallons. Hydroxypropyl guar,carboxymethyl hydroxypropyl guar, carboxymethyl guar, cationicfunctional guar, guar or mixtures thereof, are preferred polymers foruse herein as a gelling agent. Fluids incorporating polymer viscosifiersmay have any suitable viscosity depending upon the particular needs of agiven operation. For many operations, the fluids preferably have aviscosity value of about 50 mPa-s or greater at a shear rate of about100 s⁻¹ at treatment temperature, more preferably about 75 mPa-s orgreater at a shear rate of about 100 s⁻¹, and even more preferably about100 mPa-s or greater. In the case of a slickwater fracturing, alsocommonly referred to as a water fracture operation, the fluid may havesuitably low, but effective, viscosity values, and low polymer loadings,preferably less than about 15 pounds per thousand gallons, morepreferably from about 1 to about 10 pounds per thousand gallons.

Incorporating crosslinkers into the fluids further augments theviscosity of the treatment fluid. Crosslinking consists of theattachment of two polymeric chains through the chemical association ofsuch chains to a common element or chemical group, whereas such elementor group is referred to as the crosslinker. Typical crosslinkers arepolyvalent metal ions, more often zirconium or titanium ions, or borateions. Crosslinking is very sensitive to the prevailing pH. For example,crosslinking with borate ions can be performed only in alkaline media(pH>8). pH-regulating systems (“buffers”) are often required to achieveeffective crosslinking with metal ions.

Fluids used in the invention may be based upon and aqueous or nonaqueousmedium, or even gelled oil. When the fluid is based upon an aqueousmedium, the medium may be water or brine. In those embodiments of theinvention where the aqueous medium is a brine, the brine is watercomprising inorganic salts and/or organic salts. Preferred inorganicsalts include alkali metal halides, more preferably potassium chloride.The carrier brine phase may also comprise an organic salt morepreferably sodium or potassium formate. Preferred inorganic divalentsalts include calcium halides, more preferably calcium chloride orcalcium bromide. Sodium bromide, potassium bromide, or cesium bromidemay also be used. The salt is chosen for compatibility reasons i.e.where the reservoir drilling fluid used a particular brine phase and thecompletion/clean up fluid brine phase is chosen to have the same brinephase.

A fiber component may be included in the fluids of the invention toachieve a variety of properties including improving particle suspension,and particle transport capabilities, and gas phase stability. Fibersused may be hydrophilic or hydrophobic in nature, but hydrophilic fibersare preferred. Fibers can be any fibrous material, such as, but notnecessarily limited to, natural organic fibers, comminuted plantmaterials, synthetic polymer fibers (by non-limiting example polyester,polyaramide, polyamide, novoloid or a novoloid-type polymer),fibrillated synthetic organic fibers, ceramic fibers, inorganic fibers,metal fibers, metal filaments, carbon fibers, glass fibers, ceramicfibers, natural polymer fibers, and any mixtures thereof. Particularlyuseful fibers are polyester fibers coated to be highly hydrophilic, suchas, but not limited to, DACRON® polyethylene terephthalate (PET) Fibersavailable from Invista Corp. Wichita, Kans., USA, 67220. Other examplesof useful fibers include, but are not limited to, polylactic acidpolyester fibers, polyglycolic acid polyester fibers, polyvinyl alcoholfibers, and the like. When used in fluids of the invention, the fibercomponent may be include at concentrations from about 1 to about 15grams per liter of the liquid phase of the fluid, preferably theconcentration of fibers are from about 2 to about 12 grams per liter ofliquid, and more preferably from about 2 to about 10 grams per liter ofliquid.

Fluids used in accordance with the invention may also comprise abreaker. The purpose of this component is to “break” or diminish theviscosity of the fluid so that this fluid is more easily recovered fromthe formation during cleanup. With regard to breaking down viscosity,oxidizers, enzymes, or acids may be used. Breakers reduce the polymer'smolecular weight by the action of an acid, an oxidizer, an enzyme, orsome combination of these on the polymer itself. In the case ofborate-crosslinked gels, increasing the pH and therefore increasing theeffective concentration of the active crosslinker, the borate anion,reversibly create the borate crosslinks. Lowering the pH can just aseasily eliminate the borate/polymer bonds. At a high pH above 8, theborate ion exists and is available to crosslink and cause gelling. Atlower pH, the borate is tied up by hydrogen and is not available forcrosslinking, thus gelation caused by borate ion is reversible.

In some embodiments of the invention, a viscoelastic surfactant (VES) isused as a viscosifying agent. The VES may be selected from the groupconsisting of cationic, anionic, zwitterionic, amphoteric, nonionic andcombinations thereof. Some nonlimiting examples are those cited in U.S.Pat. Nos. 6,435,277 (Qu et al.) and 6,703,352 (Dahayanake et al.), eachof which are incorporated herein by reference. The viscoelasticsurfactants, when used alone or in combination, are capable of formingmicelles that form a structure in an aqueous environment that contributeto the increased viscosity of the fluid (also referred to as“viscosifying micelles”). These fluids are normally prepared by mixingin appropriate amounts of VES suitable to achieve the desired viscosity.The viscosity of VES fluids may be attributed to the three dimensionalstructure formed by the components in the fluids. When the concentrationof surfactants in a viscoelastic fluid significantly exceeds a criticalconcentration, and in most cases in the presence of an electrolyte,surfactant molecules aggregate into species such as micelles, which caninteract to form a network exhibiting viscous and elastic behavior.

Nonlimiting examples of suitable viscoelastic surfactants useful forviscosifying some fluids include cationic surfactants, anionicsurfactants, zwitterionic surfactants, amphoteric surfactants, nonionicsurfactants, and combinations thereof.

Fluids used in methods of the invention may further contain otheradditives and chemicals that are known to be commonly used in oilfieldapplications by those skilled in the art. These include, but are notnecessarily limited to, materials such as surfactants, foaming agents,crosslinking delay agent, breaker delay agents, particles, proppants,gas component, breaker aids, oxygen scavengers, alcohols, scaleinhibitors, corrosion inhibitors, fluid-loss additives, bactericides,friction reducers, latexes, emulsions, emulsifiers, and the like.

When incorporated, any proppant (gravel) can be used, provided that itis compatible with the base and the bridging-promoting materials if thelatter are used, the formation, the fluid, and the desired results ofthe treatment. Such proppants (gravels) can be natural or synthetic,coated, or contain chemicals; more than one can be used sequentially orin mixtures of different sizes or different materials. Proppants andgravels in the same or different wells or treatments can be the samematerial and/or the same size as one another and the term “proppant” isintended to include gravel in this discussion. In general the proppantused will have an average particle size of from about 0.15 mm to about2.5 mm, more particularly, but not limited to typical size ranges ofabout 0.25-0.43 mm, 0.43-0.85 mm, 0.85-1.18 mm, 1.18-1.70 mm, and1.70-2.36 mm. Normally the proppant will be present in the slurry in aconcentration of from about 0.12 kg proppant added to each L of carrierfluid to about 3 kg proppant added to each L of carrier fluid,preferably from about 0.12 kg proppant added to each L of carrier fluidto about 1.5 kg proppant added to each L of carrier fluid.

Embodiments of the invention may also include placing proppant particlesthat are substantially insoluble in the fluids of the formation.Proppant particles carried by the treatment fluid remain in the fracturecreated, thus propping open the fracture when the fracturing pressure isreleased and the well is put into production. [Any proppant (gravel) canbe used, provided that it is compatible with the base and thebridging-promoting materials if the latter are used, the formation, thefluid, and the desired results of the treatment. Such proppants(gravels) can be natural or synthetic, coated, or contain chemicals;more than one can be used sequentially or in mixtures of different sizesor different materials. Proppants and gravels in the same or differentwells or treatments can be the same material and/or the same size as oneanother and the term “proppant” is intended to include gravel in thisdiscussion. Proppant is selected based on the rock strength, injectionpressures, types of injection fluids, or even completion design.Preferably, the proppant materials include, but are not limited to,sand, sintered bauxite, glass beads, ceramic materials, naturallyoccurring materials, or similar materials. Mixtures of proppants can beused as well. Naturally occurring materials may be underived and/orunprocessed naturally occurring materials, as well as materials based onnaturally occurring materials that have been processed and/or derived.Suitable examples of naturally occurring particulate materials for useas proppants include, but are not necessarily limited to: ground orcrushed shells of nuts such as walnut, coconut, pecan, almond, ivorynut, brazil nut, etc.; ground or crushed seed shells (including fruitpits) of seeds of fruits such as plum, olive, peach, cherry, apricot,etc.; ground or crushed seed shells of other plants such as maize (e.g.,corn cobs or corn kernels), etc.; processed wood materials such as thosederived from woods such as oak, hickory, walnut, poplar, mahogany, etc.,including such woods that have been processed by grinding, chipping, orother form of particalization, processing, etc, some nonlimitingexamples of which are proppants supplied by BJ Services Co., made ofwalnut hulls impregnated and encapsulated with resins. Furtherinformation on some of the above-noted compositions thereof may be foundin Encyclopedia of Chemical Technology, Edited by Raymond E. Kirk andDonald F. Othmer, Third Edition, John Wiley & Sons, Volume 16, pages248-273 (entitled “Nuts”), Copyright 1981, which is incorporated hereinby reference.

Techniques for hydraulically fracturing a subterranean formation will beknown to persons of ordinary skill in the art, and will involve pumpingthe fracturing fluid into the borehole and out into the surroundingformation. The fluid pressure is above the minimum in situ rock stress,thus creating or extending fractures in the formation. See StimulationEngineering Handbook, John W. Ely, Pennwell Publishing Co., Tulsa, Okla.(1994), U.S. Pat. No. 5,551,516 (Normal et al.), “OilfieldApplications”, Encyclopedia of Polymer Science and Engineering, vol. 10,pp. 328-366 (John Wiley & Sons, Inc. New York, N.Y., 1987) andreferences cited therein, the disclosures of which are incorporatedherein by reference thereto.

In most cases, a hydraulic fracturing consists of pumping aproppant-free viscous fluid, or pad, usually water with some fluidadditives to generate high viscosity, into a well faster than the fluidcan escape into the formation so that the pressure rises and the rockbreaks, creating artificial fractures and/or enlarging existingfractures. Then, proppant particles are added to the fluid to form aslurry that is pumped into the fracture to prevent it from closing whenthe pumping pressure is released. The proppant suspension and transportability of the treatment base fluid traditionally depends on the type ofviscosifying agent added. The use of the aqueous energized fluidsaccording to the invention diminishes the single dominance of theviscosifying agent on proppant suspension and transport ability, as wellas improves proppant suspension and transport ability at elevatedtemperatures in excess of about 93° C., and particularly at temperaturesin excess of about 121° C.

In the fracturing treatment, fluids be used in the pad treatment, theproppant stage, or both. The components of the liquid phase arepreferably mixed on the surface. Alternatively, a the fluid may beprepared on the surface and pumped down tubing while the gas componentcould be pumped down the annular to mix down hole, or vice versa.

Example: To illustrate the method described in this invention formodeling hydraulic fracture process in a naturally fractured formation,a specific example of two intersecting hydraulic fractures as thesimplest form of fracture network is presented. The two fractures aredivided into small grids as described in paragraph 22 and the equationsas given in paragraph 25 are solved at each time increment.

In this specific example, a pre-existing, non-uniform stress field isintroduced as a result of production from an existing propped hydraulicfracture. The dual fracture model simulates a refracture treatment, inwhich a primary fracture propagates parallel to the initial proppedfracture and a secondary fracture propagates orthogonal to the primaryfracture. The normal stress distribution along the primary fracture (xaxis) and the orthogonal fracture (y axis) are shown in FIG. 4.

Additional fracture parameters used in the simulation are listed below:

Young's modulus 3 × 10⁶ psi Poisson's ratio 0.25 Fluid viscosity 100 cpLeakoff coefficient 0.002 ft/√min Pump rate 30 bpm Pump time 90 min

The predicted fracture length and flow rate history and the pressureresponse are shown in FIGS. 4 and 5, respectively. Due to the lowernormal stress along the y axis near the wellbore, the orthogonalfracture is first initiated. In the first minute of pumping, the fluidpredominantly goes into the orthogonal fracture. However, as theorthogonal fracture penetrates deeper into the formation, the stress atthe tip of the fracture increases rapidly, causing the pumping pressureto increase rapidly as seen in FIG. 5. This consequently leads to theopening and growth of the parallel fracture along the x axis when thepressure exceeds the normal stress.

The example above shows how the method described in this invention isused to simulate two intersecting hydraulic fractures. The model can beextended to simulate a primary hydraulic fracture intersecting manyintersecting fractures, representing the natural fracture joints in theformation. It can further be extended to the more complex fracturenetwork as shown in FIG. 2.

The particular embodiments disclosed above are illustrative only, as theinvention may be modified and practiced in different but equivalentmanners apparent to those skilled in the art having the benefit of theteachings herein. Furthermore, no limitations are intended to thedetails of construction or design herein shown, other than as describedin the claims below. It is therefore evident that the particularembodiments disclosed above may be altered or modified and all suchvariations are considered within the scope and spirit of the invention.Accordingly, the protection sought herein is as set forth in the claimsbelow.

The invention claimed is:
 1. A method of performing a fracture treatmenton a naturally fractured subterranean formation, said method comprising:acquiring subterranean formation layer geomechanical propertiescomprising well completion and reservoir data for the subterraneanformation, and a natural fracture network description for thesubterranean formation; inputting geomechanical properties of theformation into a model; simulating propagation of a network of fracturesin the formation; predicting if each fracture will grow and in whichdirection the fracture will branch; predicting a flow rate and pressuredistribution throughout the network of fractures by solving governingdeformation and flow equations; predicting a result of a design of thefracture treatment; and adjusting the design if the predicted result isnot satisfactory.
 2. The method of claim 1, wherein the geomechanicalproperties include elasticity property of the formation.
 3. The methodof claim 1, wherein the geomechanical properties include deformationproperty of the formation.
 4. The method of claim 1, wherein the modelis a 2D Perkins-Kern-Nordren (2D PKN) model.
 5. The method of claim 1,wherein the model is a Radial (RAD) model.
 6. The method of claim 1,wherein the model is a planar 3D model.
 7. The method of claim 1,wherein the model is a Khristianovich-Geertsma-de Klerk (KGD) model. 8.The method of claim 1, wherein the model is a Pseudo-3D (P3D) model. 9.The method of claim 1, wherein the model is a full 3D model.
 10. Themethod of claim 1, wherein said simulating is performed before or duringthe fracture treatment, and achieved by modeling progression of thefracture in small time increments with fracture growing in length insmall steps.
 11. The method of claim 10, wherein said simulating furthercomprising, at each time increment, solving the flow rate and pressuredistribution throughout the network of fractures to further satisfyboundary conditions at tips of propagating branches and at a wellborecommunicating with the subterranean formation, and the continuity, andflow rate balance at each joint connecting more than one branch.
 12. Themethod of claim 1, further comprising using a production simulator topredict productivity increase for the subterranean formation.
 13. Themethod of claim 1, wherein the subterranean formation is naturalfracture network.
 14. The method of claim 13, further comprisinginputting description of the natural fracture network into the model.15. A method of fracturing a subterranean formation, the methodcomprising: inputting elasticity property of the formation into a model;simulating propagation of a network of fractures in the formation;predicting if each fracture will grow and in which direction thefracture will branch; predicting a flow rate and pressure distributionthroughout the network of fractures by solving governing deformation andflow equations; preparing an optimum fracture fluid to achieve simulatedfracturing result; and, injecting the fracturing fluid into a wellboreat a pressure sufficient to fracture the subterranean formation.
 16. Themethod of claim 15, wherein the model is selected from the groupconsisting of a 2D Perkins-Kern-Nordren (2D PKN) model, a Radial (RAD)model, a planar 3D model, a Khristianovich-Geertsma-de Klerk (KGD)model, a Pseudo-3D (P3D) model, and a full 3D model.
 17. The method ofclaim 15, wherein said simulating is performed before or during thefracture treatment, and achieved by modeling progression of the fracturein small time increments with fracture growing in length in small steps.18. The method of claim 17, wherein said simulating further comprising,at each time increment, solving the flow rate and pressure distributionthroughout a fracture system to satisfy boundary conditions at tips ofpropagating branches and at a wellbore communicating with thesubterranean formation, and the continuity, and flow rate balance ateach joint connecting more than one branch.
 19. The method of claim 15,further comprising using a production simulator to predict productivityincrease for the subterranean formation.
 20. The method of claim 15,wherein the subterranean formation is natural fracture network.
 21. Themethod of claim 20, further comprising inputting description of thenatural fracture network into the model.